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Power System Blueprint

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Accomplishing climate neutrality by 2050 requires a zero-emissions power sector by the mid-2030s. Securing a decarbonized power system early will unlock pathways for the whole economy. One of the biggest challenges to accomplishing this ambitious goal is time—we have a need for speed if we want to meet decarbonization goals by 2035.  

This is why RAP has created the Power System Blueprint, an interactive website that allows visitors to view different options for decarbonizing Europe’s power system. The Blueprint lays out how to design the regulatory context to achieve a clean, reliable, equitable and affordable European power system by 2035. RAP pulled together the latest insights for supporting regulators, NGO’s, governments and anyone interested in the decarbonization pursuit. 

The Blueprint is designed as a schematic of regulatory solutions linked to six important central principles. In the suite of regulatory solutions (also known as factsheets),you will find comprehensive information, the most important regulatory steps and further reading. 

The decarbonization of the power sector can be done by 2035 but will require a rapid and systemic rethink of the existing European power system regulatory landscape. Within the Power System Blueprint website, you’ll find solutions to some of the some of the largest tasks we face working within this tight timeframe.   

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Electricity Pricing: Drivers, Practices and Pitfalls

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At the Financial Research Institute’s Advanced Electricity Seminar on Utility Rates and Pricing for the Future, Carl Linvill explored smart rate design fundamentals and exposed some common policy pitfalls.

国际视野:对创建“全国统一电力市场”的下一步工作建议

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近日,国家发展改革委、国家能源局发布了《关于加快建设全国统一电力市场体系的指导意见》 (发改体改〔2022〕118)。该文件为电力市场改革又向前迈出了重要一步,比如,该政策中制定了总体目标,要求在2025年前,国家市场与省(区、市)/区域市场协同运行,电力中长期、现货、辅助服务市场一体化设计、联合运营。同时,还提出优化电力市场总体设计”,“建设全国统一的电力市场体系,统一交易规则和技术标准等关于电力市场建设的要求。 

基于国际相关经验,以及对中国电力市场的了解,本文分别从以下五点提出落实该政策可考虑实施的建议,仅供参考: 

  • 以统一的算法优化区域调度的区域现货市场,是清洁能源转型的重要组成部分 
  • 中长期合同利用金融手段比物理手段更灵活、更利于可再生能源发电并网 
  • 电力现货市场的一个关键功能是在调度决策中反映不同资源的真实边际成本 
  • 输电定价不应成为统一区域市场和调度的壁垒 
  • 支持发电机容量成本回收的措施应谨慎加以限制。 

本文首登于南方能源观察(2022318

     

Foundations of Retail Electricity Rates

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​In a presentation to an Energy Systems Integration Group task force, Mark LeBel explored utility pricing principles and rate-making best practices for today’s power sector.

Energiewende im Krisenmodus braucht sozialen Zusammenhalt

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Der Krieg und das Leid der Menschen in der Ukraine halten uns alle in Atem, bringen uns aber auch als Gesellschaft näher zusammen. Die große Hilfsbereitschaft in den Grenzregionen und auch in Deutschland macht uns zusammen stark. Wie Bundespräsident Steinmeier in Litauen sagte: „Die Einigkeit und die Geschlossenheit (der Nato und der Europäischen Union) sind der Schlüssel zu unserer Stärke.“

Krisen und Kriege sind schmerzhaft und teuer. Um diese Zeit zu überstehen, braucht es den Zusammenhalt, der den Menschen die Grundbedürfnisse sichert, für die geflüchteten und die verletzlichen Verbraucher:innen innerhalb unserer Gesellschaft. Da dieses Leid eben auch unsere Energieversorgung betrifft, müssen wir hier zusammenstehen, mehr als in der Vergangenheit.

Denn in diesen Tagen wird es deutlich, dass fossile Energien teuer sind und wohl teuer bleiben werden. Der Abschied von diesen teuren und schmutzigen Ressourcen kostet allerdings ebenfalls Geld und Zeit. Für den einzelnen geht jede Umstellung auf eine Wärmepumpe und höhere Energieeffizienz mit hohen Investitionskosten einher, welche wir uns trotzdem leisten können müssen. Denn die zusätzliche Rechnung, die Deutschland durch die gestiegenen Gaspreise stemmen muss, wird sich wohl auf einen hohen zweistelligen Milliardenbetrag im Jahr belaufen.

Für einzelne Verbraucher:innen mit Gasheizung bedeutet das etliche hundert Euro im Jahr zusätzlich, bei schlechten Gebäuden und damit hohen Verbräuchen können es auch leicht mehr als 1000 Euro werden. Die Mehrwertsteuer erhöht die Kosten noch weiter. Im Vergleich dazu führt die beschlossene Senkung beziehungsweise Überführung der EEG-Umlage in den Bundeshaushalt zu einer Entlastung des durchschnittlichen Haushalts um gut 200 Euro im Jahr.

Durch die gleichzeitig stark steigenden Strompreise werden die Stromrechnungen der Verbraucher:innen wohl trotzdem nicht sinken. Sowohl für den Gas- als auch der Stromsektor sind das Mittelfristbetrachtungen, das heißt, sobald die hohen Großhandelspreise vollständig in die Endkundentarife eingepreist sind.

System und Regulierung sind unsozial geprägt

Diese Kostensteigerungen lassen sich mittelfristig nur durch mehr erneuerbare Energien und eine größere energetische Unabhängigkeit bekämpfen, mit Freiheitsenergien, wie Herr Lindner sagte. Dazu gehört die schnellere Verbrauchsminderung durch Effizienzmaßnahmen und eine beschleunigte Elektrifizierung, insbesondere im Wärmesektor durch Wärmepumpen und Wärmenetze. Ein fortgesetzter Einbau von Gasheizungen in Neubauten und ein weiterer nachfrageorientierter Gasverteilnetzausbau passen dazu nicht. Hier bedarf es einer sofortigen Richtungsänderung, die die Verringerung unserer Import-Abhängigkeit einleitet als auch die langfristigen Energiewendekosten begrenzt. Kosten, die am Ende sonst alle Verbraucher tragen, im Verhältnis die vulnerablen Verbrauchergruppen aber stärker betreffen.

Unser Energiesystem und dessen Regulierung kann jedoch kaum mit sozialen Absicherungen oder Hilfen aufwarten, eher ist das Gegenteil der Fall. Beispiele sind:

Auf der anderen Seite fördern wir mit Milliarden Euro Kaufprämien für E-Pkw, Pendlerpauschalen und Wallboxen wie auch energetische Sanierungen in Eigenheimen, während die bedürftigsten Verbraucher:innen in den energetisch schlechtesten Gebäuden wohnen (müssen), auf deren Energiestandard oder Energieträger sie keinen Einfluss haben. Unser Sozialsystem versucht, die Mehrkosten der Bedürftigsten mittels Arbeitslosengeld II und durch Einmalzahlungen zu kompensieren. Damit bleiben jedoch die Wohnsituationen wie auch Hilfen für die unteren Einkommensgruppen insgesamt außen vor.

Die Folgen der hohen Gaspreise werden noch unterschätzt

Es ist richtig, den Umstieg auf nachhaltige und saubere Lösungen zu fördern, jedoch im Sinne einer gemeinsamen Stärke, wo es nötig ist. Dazu gehören neben den Anreizen auch Besteuerungen und das Ordnungsrecht. In der Krise wird sich deutlicher denn je zeigen, wie weit wir das Ordnungsrecht über den Artikel 14 des Grundgesetzes bemühen und Eigentum über Gebote und Verbote verpflichten. Abweichend davon spielt im selbstgenutzten Eigentum die Sichtbarkeit der mittel- bis langfristigen Kosten die wichtigste Rolle.

Wenn es sich jedoch um vermieteten Wohnraum handelt, greift dieser Ansatz zu kurz. Die Energiekosten werden für fast jeden Mieter stark steigen. Die bisher diskutierten Größenordnungen von Pro-Kopf-Rückzahlungen oder Vorhaben für eine CO2-Kostenteilung mit dem Vermieter werden daran nur wenig ändern. Trotzdem diskutiert Deutschland maßgeblich die Spritpreise. Sowohl die Opposition als auch die FDP wollen die Preise durch Steuernachlässe auf breiter Basis senken, obwohl aus volkswirtschaftlicher und geopolitischer Sicht ein schnellerer Abschied geboten ist.

Wie wenig ausgewogen diese Forderungen sind, zeigt sich im Vergleich. Die Rohölpreise haben sich „nur“ verdreifacht, während es beim Großhandelspreis Gas aktuell fast eine Verzehnfachung innerhalb eines Jahres ist. Die Auswirkungen in den Gas-Tarifen sehen wir erst in einigen Monaten, jedoch mit viel weiterreichenden sozialen Folgen.

Auch ein reiches Land wie Deutschland wird sich ohne anderweitige, massive Steuererhöhungen kaum eine Kostenübernahme für fossile Energien in der Breite leisten und gleichzeitig die Förderung von Einsparungen und erneuerbaren Energien erhöhen können. Angedachte Entlastungen müssen sich daher stärker an den sozialen Auswirkungen und den Langfristzielen orientieren. Preissignale zu mindern, stellt jedoch das Gegenteil dar. Wenn unsere Gemeinschaft die gemeinsame Stärke besitzt, die unser Bundespräsident bekundet hat, schaffen wir es, die Krise als Chance zu nutzen.

Es ist dringlicher denn je, die Verteilung der Kosten und die Ausgestaltung der Unterstützungen in der begonnenen Transformation fair und sozial zu gestalten. Nutzen wir diese Chance. Jetzt.

Eine Version dieses Artikels erschien in Tagesspiegel Background.

Rate-Making Principles and Net Metering Reform: Pathways for Wisconsin

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A growing number of states have considered reforms to their net metering practices in recent years, a period of decreasing prices for distributed energy resources, rapid changes in technology and evolution of the electricity system. 

Depending on its design, a net metering program can advance specific policy goals while maintaining sound principles of rate design. Trade-offs in rate design are inevitable as regulators balance different priorities, such as rates that accurately reflect cost causation and rates that are simple for customers to understand. Reliance on long-standing rate-making principles will be key to prudent decision-making. 

This paper was produced for the Wisconsin Public Service Commission as part of its review of the state’s net metering practices. 

The authors examine net metering approaches in the context of general rate-making principles and policy goals. They then explore considerations associated with specific design components of net metering tariffs — including eligibility, metering, netting intervals and customer buyback credits — and the methods used to calculate fixed, energy-based and demand-based charges. The final section details recent net metering reforms in seven states: North Carolina, South Carolina, California, Arizona, Minnesota, New York and Michigan.

Cost-Based Rate Design Reforms for the Modern Grid

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​In a presentation for a California Public Utilities Commission en banc hearing on affordability, Mark LeBel shared advanced electric rate design principles and examples.

Europe needs smart charging of all EVs now

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A recent pan-European survey found that consumers prefer electric vehicles (EVs) over conventional cars. Last month’s EV sales surpassed those of diesel models in Europe for the first time. Charging the growing number of EVs at our homes, workplaces and public parking lots ‘smartly’ is essential to lower the cost of integrating electric vehicles into the power system and capture the numerous benefits EVs offer.

Smart charging of an electric vehicle means shifting charging to a time when it is cheapest for consumers and best for the grid. This managed charging unlocks broader benefits, such as efficient grid operation and integration of increasing shares of renewable energy, by adjusting the demand for charging to the actual supply. Europe is also seeing a growing market for digital smart charging services — services that will improve its use of power systems.

By contrast, without smart EV charging, millions of euros will be lost in costly, unnecessary power system upgrades, as recent studies from France and Germany suggest. Several legislative proposals in the Fit for 55 package have opened a critical window of opportunity to ensure smart charging is the default choice, thus saving money, energy and emissions.

Without smart EV charging,
millions of euros will be lost in costly,
unnecessary power system upgrades.

First on the agenda is a regulation that will establish a European framework for electric vehicle charging infrastructure on public roads, the Alternative Fuels Infrastructure Regulation. The EU Parliament and Council will soon vote on the proposal. By providing a public charging network Europe-wide, this regulation can boost the market for smart charging services, keeping pace with the benefits created by rapidly growing shares of EVs. For this to happen, the regulation needs to require smart charging capabilities at all charging points as well as retrofits of older ones.

Smart tariffs to complement technology and infrastructure

Being able to shift EV charging to cheaper hours can help consumers save hundreds of euros a year through a growing selection of smart tariffs and services. And smart charging is easy: Based on time-varying price signals, smart charging devices and apps determine when and at what speed EVs charge. Drivers do not need to compromise their mobility needs, as they can override these settings at any time. One powerful grid benefit of consumers charging at least cost is the use of renewable energy that might otherwise have been curtailed, thereby boosting the use of clean resources. Europe’s recent electricity reforms have recognised this correlation by mandating that Member States offer more smart tariffs to consumers. Transport legislation needs to follow: The time is now to build on the benefits of more dynamic tariffs and require smart charging infrastructure to be the default, so that smart charging services can prosper.

Transport legislation needs to make charging smart, wherever you go

To make sure smart charging is the default option for all EV drivers in Europe, all charging points need to be ready for smart charging services with smart meters, digital connectivity and third-party access. These requirements should apply to all public charging points covered by the new Alternative Fuels Infrastructure Regulation, including high-power chargers and not only the ‘normal,’ lower speed chargers as the EU Commission suggests in its legal proposal.

All chargers, slow and fast, for cars and for trucks, are easier to use and integrate into the grid if they are smart. This allows charging vehicles to adapt to varying grid conditions, the actual available grid capacity and local renewable energy production. As the charging market grows, intelligent fast chargers will also make it easy to share available power among groups of chargers in hubs. As a recent study on truck charging along motorways shows, managing power flows smartly is key to reducing costs without affecting service levels. Setting smart charging requirements through the Alternative Fuels Infrastructure Regulation for all chargers lays the foundation for market growth for these and other innovative solutions.

The EU Commission rightfully proposes that existing chargers also need to be retrofitted accordingly. Ensuring existing chargers can also deliver the value of smart charging services offers consistency across the pan-European charging network.

A coherent framework for a smart clean transport eco-system

The importance of equipping charge points to deliver smart charging services also extends to private infrastructure and buildings, as most EV drivers will charge at home or at work. By increasing ambition in the Energy Performance of Buildings Directive and the Renewable Energy Directive, decision-makers can help complete the smart charging landscape.

European decision-makers will soon consider requirements in Europe for equipping buildings and homes with charging points or, at the very least, pre-cabling them for upcoming infrastructure needs. Sufficient ambition in the upcoming Energy Performance of Buildings Directive can extend this obligation to all home parking spots, making all charging equipment smart and, therefore, future proof.

A solid definition of what smart charging can offer to Europe’s future energy markets, grids and consumers is crucial to make smart charging the default choice. The Renewable Energy Directive proposal makes a fair start, but an earlier version of the Directive’s Article 20 offered greater recognition of the potential of smart charging to create societal benefits.

Harmonising smart charging at work, at home and at public charging stations creates an EU-wide digital market for smart charging services. That makes it easier to reap the benefits of smart charging, not just for EV drivers, but also for energy markets and for grid operators that can use the inherent flexibility in EV charging to run their grids more efficiently. While revising these files, it is important for lawmakers to pass on the benefits of smart charging to the actual end user, the EV driver. Focus on the user’s interests is crucial. This means increasing customer choice through market mechanisms and building trust, as opposed to models where EV charging is fully controlled by grid operators, such as it is currently the case in Germany.

The time is now

E-mobility should be accessible to all, wherever one is in Europe. Members of Parliament and other stakeholders have the chance to amend the charging infrastructure laws under review to make sure benefits of smart EV charging reach all, at minimal cost, and thus accelerate the energy transition. Creating a European market for smart charging services and matching user preferences to energy system needs will drive down costs for all. These developments will, in turn, persuade even more consumers to switch to electric, turning petrol and diesel vehicle sales into relics of the past.

A version of this article originally appeared on Euractiv.

Photo: Ivan Radic via Flickr.

The Complex Landscape of Net Metering Reform in California: Ensuring A Smart TOU Rate Foundation

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California, long a leader in rooftop solar, is now wrestling with the complications — as illustrated by the current debate over the California Public Utility Commission’s proposed decision on “net energy metering 3.0,” released last month. Before the end of 2021, we began a series of blogs looking closer at this issue by noting that much of the public debate over the proposed decision has focused on the new “grid participation charge,” which would be structured as a monthly fee per kW of installed capacity.

Another issue under consideration, on which we’ll focus in this second installment, is time-of-use (TOU) rates.  Getting TOU rate design right should be emphasized both in the short term — as an alternative to a large grid participation charge — and in the context of longer-term rate design reform. In short, ensuring that TOU rates for new DER customers have sufficiently low daytime prices is likely to be a more economically efficient way to reduce cost shifts.

The proposed decision does have a brief discussion about the importance of bigger on-peak/off-peak price ratios in TOU rates, and it imposes a requirement that new solar customers go onto such a rate. The proposed decision lists an existing rate that qualifies for each of the three investor-owned utilities, but it does not show those rates or discuss their structure. Those rates are:

These rates do have a bigger on-peak/off-peak price ratio than other TOU rates available in California, but that should not be the only consideration in the construction of a fair and efficient TOU rate. The time period structure, namely the hours that are on-peak, off-peak, and other designations, and the relative levels across each period are all important as well. The 2021 PG&E EV2-A rate in the summer is shown in Figure 1.

Figure 1: PG&E Summer Price Structure Under the EV2-A Rate in 2021

Under any DER compensation structure where a customer can reduce their bill with lower imports from the grid, a substantial portion of the compensation for installing solar will come from the retail rate during daytime hours. As shown in Figure 1, that rate was 19 cents per kWh for PG&E in 2021 and is now 21 cents in 2022. Under the SCE TOU-D-PRIME rate, the daytime kWh rate is 19 or 20 cents per kWh, depending on the season. The SDG&E EV-TOU-5 rate has a more complex structure, but in the summer the daytime kWh rate is even higher, now at 39 cents per kWh in 2022. To the extent that solar customers are overcompensated, and thus causing costs to be shifted unfairly to other customers, this would be a major reason why. If the daytime kWh rate can be reasonably lowered, it could address a substantial portion of any cost shifting and substitute for other potential charges on DER customers, such as the grid participation charge.

The goals of TOU rate design are much the same as all rate design, and indeed utility regulation generally. The desire of economic efficiency must be balanced with the need for customer understanding, costs must be allocated equitably across all customers, and overall revenue levels must provide the utility a reasonable opportunity for a fair rate of return. Compared to flat volumetric kWh rates, TOU rates are attempting to better correspond to predictable fluctuations in the marginal costs, both short- and long-run, of the electric system. Seasonal distinctions can also be important in a TOU rate structure, although such distinctions are possible in simpler rates.

In California and other states where solar is a major part of the resource mix, a particular pattern for marginal costs (in this context, referred to “avoided costs”) is emerging. A longstanding process at the CPUC has led to the annual submission of an “Avoided Cost Calculator” by the consulting firm E3. While the 2021 ACC shows an avoided cost pattern for 2022 that roughly tracks PG&E’s EV2-A rate, by 2024 a different pattern starts to emerge. The daytime hours start to have distinctly lower avoided costs and this trend grows over time. An efficient TOU structure will track these avoided cost patterns with lower prices during daytime hours.

Why does the cost structure expected in California in a few years matter for rate design today? First, anticipating where rate design needs to go in the future is helpful for considering changes over time. Many solar programs have guaranteed customers that they can stay on a particular rate structure for a given period of time to avoid adverse financial impacts. Under those circumstances, it would be wise to implement a rate structure that reflects expected conditions in the future.

Second, these particular rates drive much of the other analysis in the proposed decision about cost shifting, as well as the grid participation charge and the market transition credit. For example, a major reason that SDG&E customers do not get a market transition credit under the PD is likely that the high daytime kWh price in the summer that provides much of their compensation is so generous. If a new rate with lower daytime prices were to be implemented in two years and new solar customers were required to go on that rate, it would upend all of the analysis that went into structuring the grid participation charge and market transition credits.

A third, perhaps more technical, reason is that when you are structuring cost recovery, the relative price elasticity of demand can be considered. As solar costs have declined, overall daytime net consumption has become more elastic (e.g., readily responsive to prices) exactly because of the option to install solar. This reason alone may be sufficient to get out in front of these issues and reallocate revenue collection away from daytime hours to other parts of the rate.

This shows why changing TOU rate structures, particularly with lower daytime prices, is a superior option to the grid participation charge. Hawaiian Electric has already structured some of its TOU rates to have the lowest prices in the daytime, as shown in Figure 2.

Figure 2. Hawaiian Electric Residential TOU Rate for January 2022

Hawaiian Electric Residential TOU Rate for January 2022

While both methods can correct for a cost shift in a spreadsheet model, the grid participation charge is likely to push customers to shrink their solar systems and, even worse, avoid interaction with the grid. A lower daytime price, on the other hand, helps shift load — particularly flexible loads like EVs and battery storage — to the daytime when generation resources are expected to be abundant and relatively low-cost. This is why rate design was one of RAP’s strategies for Teaching the Duck to Fly.

It is important to note that the correct daytime price for these rates should not necessarily drop all the way to the 3-4 cents of avoided costs shown in the E3 avoided cost calculator. First, an extraordinarily low price in the daytime would by itself undercut the economics of solar installations, so the impact on adoption rates should be considered. Second, an extraordinarily low price in the daytime might spur a customer overreaction — moving significantly more consumption than might be expected to the daytime. As a result, the principle of gradualism likely dictates that the pace of change should be moderated appropriately.

Furthermore, the E3 avoided cost calculator has many good features, but it likely does not include full long-run marginal costs for delivery. For example, one expert, testifying in the NEM 3.0 docket on behalf of agricultural electricity consumers, argued that current methods ignored the long-run marginal cost of new transmission needed to deliver utility-scale generation and estimated that marginal cost at 3.75 cents per kWh. Including this type of marginal cost is crucial to establish fair competitive terms between utility-scale solar and local resources. Otherwise, the scale is unfairly weighted towards the side of utility-scale resources. While the E3 avoided cost calculator indicates that there are marginal costs for transmission capacity in the evening peak hours, there are no marginal transmission capacity costs in the daytime hours. If that is the case, this would indicate an issue that should certainly be explored and corrected in the future.

Unfortunately, changes to TOU rate structures were not considered at all in the proposed decision and were not raised prominently in the docket. The solar industry and its allies worry that creating new rate designs that only apply to solar customers risks unfairly singling them out. RAP believes that any new rate structures should be fairly and efficiently designed and should be technology-neutral in order to be applied to a broad swath of customers. On the other side, the utilities focused on their proposal that became the grid participation charge, an option that appears to be unfair and inefficient. If the CPUC declines to adopt the current proposed decision, restructuring the TOU rates would be a sensible option to put on the table, along with other options discussed in our first blog in this series. At a minimum, considering how future reforms to TOU rate structures would require changes to the grid participation charge is necessary.

Forward-looking TOU rates that include lower daytime prices offer an opportunity to advance NEM reform goals while improving customer incentives. More generally, technology-neutral rate design reforms should be the path forward, not the arbitrarily sized installed capacity charges designed to claw back revenue in the proposed decision.